It’s a shale world and it’s only getting bigger, according to Ziff Energy Group’s natural gas consulting manager.
Ed Kallio, speaking at the LDC Forum Mid-Continent in Chicago, offered the crowd his firm’s outlook for North American natural gas supplies through 2020. Producers, he said, are continuing to migrate to the shales in a big way and for a big reason. It’s simply easier to produce shale gas today than to dig for gas in depleted conventional basins.
Why is gas drilling across North America still fairly steady when the cost curve is higher than current gas prices? Kallio offered a litany of reasons: some producers are drilling to hold leases by production, some have favorable gas pricing hedges in place, and some are relying on the investments from their wealthy, foreign joint venture (JV) partners.
“Foreign firms are coming in, amassing large land positions in many of the shales,” and if a producer is “looking for money to develop, where are you going to go? You are going to go to somebody who wants to learn about shale,” he explained.
Another big reason that drilling has not collapsed is the move by some producers to capture the shales’ gas liquids content. “It reduces the economics in some of the shales…For instance in the Eagle Ford [shale in South Texas], producers are getting roughly twice the gas price. So if gas is selling for $4, with liquids it’s in the $8 range.”
At some price point, however, the Ziff consultant thinks gas drilling will have to slow down — and he thinks it will be sooner rather than later.
“I don’t see too many months going forward on hedges…” and today it’s difficult to obtain a hedge “at over $5.50.” In a lot of plays, it may “still be economic [to drill] at $5.50, but if it’s in the higher cost [shales], you’ll be out of business if you keep drilling.”
Ziff has done a lot of research on the economics of specific shale plays across the United States and Canada, and Kallio offered a few tidbits.
The Horn River Shale in northeastern British Columbia (BC) is “a beautiful play, but its in the wrong place,” in an area with little infrastructure and “basis differentials to contend with. It will not be drilled as quickly as the Haynesville or Marcellus [shales], for instance. It will get to 2-3 Bcf/d,” but it will take some work.
The proposed liquefied natural gas (LNG) project under way by EOG Resources Inc. and Apache Corp., to liquefy the shale gas at Kitimat, BC, and move it to Japan, is a good idea, he said. “It would turn the play into an Asian market that links to oil prices, and it makes a lot of sense…They need an export license, however…”
The Woodford Shale in the Midcontinent,which has been overshadowed by some of the bigger name plays, should become a 2 Bcf/d play by 2020, said Kallio. “It’s a little higher cost, so it’s not being drilled as quickly.” But the granddaddy Barnett Shale in North Texas “has pretty much topped out…we don’t feel it’s going to grow.”
Down in South Texas in the Eagle Ford Shale, there are “very good economics, a good liquids uplift.” And in the Haynesville Shale, which straddles northwestern Louisiana and East Texas, should become a “close to 4 Bcf/d” play by 2020.
The biggest play production-wise in the next nine years may be the Marcellus Shale, Kallio said.
“When we forecast in any play, all shale plays, we have to forecast in [the number of well] completions we expect, the productivity of the wells and the decline rate,” Kallio noted.
Based on Ziff data, the Marcellus Shale should produce “close to 5 Bcf/d” by 2020. But he didn’t make it a given. “This is forecasting, not an exact science…”
Some of the plays will have “higher production, some lower, but we feel by 2020 that we will have about 24-25 Bcf/d out of the shales,” he said. “Think about 2008. Who’d have ‘thunk’ it?
“This is because of advancements in technology, horizontal drilling, multi-stage fractures [fracs]. Each frac can add a Bcf, and the more frac stages that you have, the more recoverable reserves you get, which drives down F&D [finding and development] costs on a unit basis…That’s why these shales are growing; they’re cheaper on a cost curve…the conventional plays are higher cost…
“But there’s only so much you can do.”
Across the continent, conventional gas production continues to fall while unconventional output grows.
Gulf Coast gas production ” is in decline,” Kallio said of Ziff’s outlook for on regional gas output. “It’s down to about 6 Bcf/d this year [and will be] about 4 Bcf/d by 2020…”
Some energy analysts — and producers — are keen about the gas prospects in the Rocky Mountains, but Ziff doesn’t “see the Rockies as a prolific region going forward. There’s not a lot of growth in the Rockies beyond 13.5-14 Bcf/d” by 2020. “Again, it has higher costs…”
However, Kallio acknowledged that there much that is unknown about the Rockies and its diverse basins, some of which are shale.
“I’m hedging a little bit, but the forecast to 2020 is based on the information we have now, the infill drilling you can do…”
By 2020 Ziff expects to see about 1-3 Bcf/d of LNG imported into North America, and by then “northern gas, a little bit coming in by 2019, 2020…from the Mackenzie Gas Project in northern Canada and the Alaska gas…that could happen. We’ll see.”
“We are forecasting 28% out of conventional sources by 2025, and unconventional…by then is 52%,” Kallio said of North American gas output. “We’ll need some new gas [supplies] through 2025, a little bit of LNG…By then some shales will top out, like the Barnett, and we’ll need a little more LNG…some from Alaska…”
The costs to produce unconventional gas in Canada are “very high,” Kallio said. Without taking into account the gas liquids content of various plays, “the cheapest one” to produce currently, he said, is the Montney Shale,” a British Columbia shale play where there is some midstream infrastructure in place.
“Other Canadian plays have very high costs…Supply is growing in some regions and going in other regions…,” but conventional gas reserves are is declining in Western Canada,” and producers are moving “up and out” to the emerging shales.
On the demand side, Ziff sees gas demand growing through 2020. “Why? The biggest reason is the gas demand for power generation,” Kallio said. Gas demand for power generation is at 21.2 Bcf/d now and it should be at around 28 Bcf/d by 2020.”
Hydro supplies and renewables should have 6% of the market, up from 2% by 2020, he said. “Even if you triple renewable energy, it won’t amount to much…” Ziff also expects nuclear power to ‘grow a little bit” by 2016.
Meanwhile, “coal is flat over this period. Coal is not going to grow. Who’s going to invest in coal right now?”
Depending on the outcome of a U.S. climate change bill, coal production is flat, according to Ziff research. If coal resources were to “come out and we started to wean off, by 2020 gas additions for power generation would be another 30 Bcf/d…”
Kallio acknowledged that it’s “not feasible to take coal off line…it will be down some, but gas demand is growing…”
Another “big demand sink for natural gas” is oil demand, which is growing especially in Canada from oilsands projects. “It will go to 3 million b/d by 2020, and right now we’re burning 1 Bcf/d in oilsands projects. We think it will be close to 3 Bcf/d by 2020 for demand in the oilsands…”
If all of the six proposed oilsands projects now before Canadian regulators were approved and online by 2020, “we would need 6 Bcf/d by 2020.” However, “there’s going to be delays. We feel the 3 Bcf/d is reasonable.”
As to its regional view of gas demand outside of Canada, Kallio said Ziff is predicting demand would be “really flat” on the Pacific Coast to 2020. Otherwise, power demand in most sectors is seen growing across North America.
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